2015-02-17 february investor presentation

Investor

Presentation

February 2015

Forward-Looking Statements

Except for historical information contained herein, the statements, charts and graphs in this

presentation are forward-looking statements that are made pursuant to the Safe Harbor Provisions

of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the

business prospects of Pioneer are subject to a number of risks and uncertainties that may cause

Pioneer's actual results in future periods to differ materially from the forward-looking statements.

These risks and uncertainties include, among other things, volatility of commodity prices, product

supply and demand, competition, the ability to obtain environmental and other permits and the

timing thereof, other government regulation or action, the ability to obtain approvals from third

parties and negotiate agreements with third parties on mutually acceptable terms, completion of

planned divestitures, litigation, the costs and results of drilling and operations, availability of

equipment, services, resources and personnel required to perform the Company's drilling and

operating activities, access to and availability of transportation, processing, fractionation and

refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its

development activities as scheduled, access to and cost of capital, the financial strength of

counterparties to Pioneer's credit facility and derivative contracts and the purchasers of Pioneer's

oil, NGL and gas production, uncertainties about estimates of reserves and resource potential and

the ability to add proved reserves in the future, the assumptions underlying production forecasts,

quality of technical data, environmental and weather risks, including the possible impacts of

climate change, the risks associated with the ownership and operation of the Company’s industrial

sand mining and oilfield services businesses and acts of war or terrorism. These and other risks are

described in Pioneer's 10-K and 10-Q Reports and other filings with the Securities and Exchange

Commission. In addition, Pioneer may be subject to currently unforeseen risks that may have a

materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements

except as required by law.

Please see the appendix slides included in this presentation for other important information.

2

Spraberry/Wolfcamp Gross

Production By Operator3

(MBOEPD)

Pioneer At A Glance

Top U.S. Fields By Rig Count2

(Pioneer Operated Count in Green – 16 rigs)

1) Reflects Alaska, Barnett Shale and Hugoton production as discontinued operations

Best performing E&P stock in S&P 500

since 2009

Strong hedge positions through 2016

Investment grade

~$24 BCurrent

Enterprise

Value

$1.85 B2015 Planned

CapEx

>11 BBOEProved

Reserves +

Net Resource

Potential

33) December 2014 DrillingInfo data, gross reported oil and wet gas

2) Baker Hughes Rig Count (02/13/15) and PXD Internal; includes horizontal and vertical rigs

201

MBOEPDQ4 2014

Production1

Oil50%

Gas29%

NGL21%

*max rig count in 2014

4

2015 Outlook

In response to the current low oil price environment and reduced margins,

Pioneer is significantly reducing spending and is focusing on optimizing returns,

capital efficiency and production by high-grading drilling activity in the best

areas of the Spraberry/Wolfcamp and Eagle Ford Shale

− Preserves strong cash position and balance sheet until margins improve

Pioneer is reducing horizontal drilling activity in the Spraberry/Wolfcamp and

Eagle Ford Shale to 16 rigs by the end of February (~50% reduction)

− 6 rigs in northern Spraberry/Wolfcamp, 4 rigs in southern Wolfcamp JV and 6 rigs in Eagle

Ford Shale

− Shutting down vertical drilling program in Spraberry/Wolfcamp by the end of February

Infrastructure development projects, including construction of the

Spraberry/Wolfcamp water system and expansion of the Brady sand mine, will

be slowed down

Reduction in drilling activity and infrastructure build-out results in planned

capital expenditures of $1.85 B for 2015

− ~45% reduction from 2014 capital spending for continuing operations

− $1.6 B for drilling and $0.25 B for water infrastructure, vertical integration and facilities

− Capital program funded from operating cash flow of $1.7 B and cash on hand of $1.0 B

5

2015 Outlook (cont.)

Forecasting 2015 annual production growth from continuing operations of 10%+ based on

$1.85 B capital budget and high-graded drilling program

− Growth primarily first-half weighted with Q4 2015 production essentially flat with Q4 2014

− Forecasting oil growth of 20%+

Aggressively improving margins through efficiency gains and cost reductions from service

companies and suppliers

− Already realizing ~10% decrease in drilling costs in 2015 compared to 2014

− Expect costs to decline at least 20% by year-end 2015 compared to 2014

Prepared to add horizontal rigs later in 2015 in response to reduced costs and/or

improved oil price environment

Continuing to pursue divestment of Eagle Ford Shale Midstream business

Cash flow protected by:

− Derivative coverage for forecasted oil production of ~90% for 2015, with most volumes protected by

swaps at $71 per barrel; also have significant portion of 2016 oil production covered by 3-way collars

with attractive downside protection

− Derivative coverage for forecasted gas production of ~90% for 2015, principally with 3-way collars with

attractive downside protection

Strong balance sheet, planned EFS Midstream sale and strong derivatives position

provide Pioneer with the financial flexibility to prudently manage through a protracted

oil price downturn or quickly ramp up drilling activity if margins improve significantly

1.00

2.00

3.00

4.00

5.00

6.00

30.00 40.00 50.00 60.00 70.00 80.00 90.00

NYMEX Oil Price ($/BBL)

NY

MEX G

as

Pri

ce (

$/M

CF)

Sensitivity to Commodity Prices ($ MM)

6

2015E Capital Spending and Cash Flow1

1) Capital spending excludes asset retirement obligations, capitalized interest and G&G G&A

Drilling Capital: $1.6 B

– $1,050 MM northern Spraberry/Wolfcamp (65% of total)

o $735 MM for horizontal drilling program

o $20 MM for vertical drilling program

o $225 MM for infrastructure and land

o $70 MM for gas processing facilities

– $120 MM southern Wolfcamp joint venture area

(net of carry)



– $390 MM Eagle Ford Shale



– $40 MM Other Assets

Other Capital (water infrastructure, vertical

integration and facilities): $250 MM

Capital program funded from:

– Operating cash flow of $1.7 B

– Cash on hand ($1.0 B at the end of Q4 2014)

2015E Average Price

$55/BBL oil and $3.00/MCF gas

Capital program of $1.85 B

$5/BBL oil price change = ~$40 MM of cash flow

$0.50/MCF gas price change = ~$10 MM of cash flow

155

166176

186

201

2013 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

7

45% Oil

1) All periods exclude Alaska, Barnett Shale and Hugoton production as discontinued operations 2) FY 2015 production expected to be negatively impacted by ~5 MBOEPD compared to 2014; negative production impact reflects loss of ~4 MBOEPD due to ethane

rejection in Spraberry/Wolfcamp and Eagle Ford Shale and ~1 MBOEPD due to downtime associated with the severe winter weather in January in Spraberry/Wolfcamp (~3 MBOEPD in Q1)

182 MBOEPD

201448% Oil

Forecasting 2015 Production Growth Range of 10%+1

2015E~53% Oil

Prepared to add rigs

if margins improve

200+ MBOEPD2

192-197

Impacted by severe weather in

Q1 and FY ethane rejection2

8

Liquidity Position (12/31/14)

Net debt (net of cash balance of $1,025 MM): $1.6 B

Unsecured credit facility availability: $1.5 B

Net debt-to-book capitalization: 16%

1) Excludes issuance discounts and deferred hedge losses of ~$25 MM

Maturities and Balances1

Unsecured credit facility matures in 2017

Investment grade rated

2016

$600 MM

3.950%

2017

$455 MM

5.875%

2022

$450 MM

6.875%

$1.5 B unsecured credit facility

2018

$485 MM6.650%

$450 MM

7.500%

2020

$250 MM

7.200%

2028

(undrawn as of 12/31/14)

Pioneer’s Q4 2014 Northern Spraberry/Wolfcamp Program

Placed 36 horizontal Wolfcamp Shale

wells on production during Q4

– For each interval, Q4 wells are outperforming the

average of all previously drilled wells in that interval

Placed 4 horizontal Lower Spraberry Shale

wells on production during Q4

– Early production data similar to previously drilled Lower

Spraberry Shale wells

– 80% oil content; average lateral length of ~5,600 feet

Placed 1 Jo Mill Shale well and 2 Middle

Spraberry Shale wells on production in Q4

– Jo Mill Shale well delivered Pioneer’s highest 24-hour

peak IP rate to date for this interval of 914 BOEPD with

81% oil content and lateral length of ~4,850 feet

– 2 Middle Spraberry Shale wells had an average 24-hour

peak IP rate of 417 BOEPD with 76% oil content and an

average lateral length of ~6,000 feet

Q4 Wolfcamp POPs Interval

20 Wolfcamp B

11 Wolfcamp A

5 Wolfcamp D

9

9

3

5

2

5

8

2

2

2

3

Jo Mill

Lower Spraberry

Wolfcamp A

Wolfcamp B

Wolfcamp D

Middle Spraberry

2

Production data continues to support strong

EURs in the northern Spraberry/Wolfcamp area

Pioneer’s Northern Spraberry/Wolfcamp Acreage

-

20

40

60

80

0 30 60 90

Days On Production

-

20

40

60

80

0 30 60 90

Days On Production

-

20

40

60

80

0 30 60 90

Days On Production

Average 24-hour peak IP rate of 36

Q4 Wolfcamp wells:

~1,700 BOEPD with 76% oil content

Horizontal Wolfcamp Production Data: Q4 vs. Historical Wells

10

Wolfcamp A Wolfcamp B

Wolfcamp D

Q4 wells (11)avg. lateral: ~8,700 feet


Historical wells (33)avg. lateral: ~7,700 feet



Cum

ula

tive P

roducti

on (

MBO

E)


Cum

ula

tive P

roducti

on (

MBO

E)

Cum

ula

tive P

roducti

on (

MBO

E)

For each interval, Q4 wells outperforming

average of all previously drilled wells in that

interval

Reflects longer average lateral lengths and

improved knowledge of the play

Q4 Wolfcamp A and B wells expected to be

representative of high-graded 2015 drilling

program

Northern Spraberry/Wolfcamp: High-Grading Drilling Activity in 2015

Reducing horizontal rig count to 6 rigs by the end

of February

High-grading drilling activity to areas and intervals

with the highest EURs and net revenue interests

– Focusing on locations where horizontal tank batteries

exist

Expect to place 85 to 90 horizontal wells on

production during 2015 compared to 97

horizontal wells in 2014

– 70% Wolfcamp B wells; remainder split between

Wolfcamp A, Wolfcamp D and Lower Spraberry Shale

wells

– Average D&C cost per well: ~$9 MM assuming average

lateral lengths of ~9,000 feet and an average 10% cost

reduction compared to 2014

– Expected to generate EURs averaging ~900 MBOE with

before-tax IRRs up to 55% at current strip prices

(average oil price of $55 per barrel during 2015)

Shutting down vertical drilling program by the end

of February

Pioneer’s Northern Spraberry/Wolfcamp 2015 Drilling Areas

11

Plan to spud ~60 wells in 2015 utilizing

2-well and 3-well pads

~90% Wolfcamp B; ~10% Wolfcamp A

Southern Wolfcamp JV: High-Grading Drilling Activity in 2015

Reducing horizontal rig count to 4 rigs by

the end of February

High-grading drilling activity to areas and

intervals with the highest EURs and net

revenue interests

– Focusing on locations where horizontal tank batteries

exist

Expect to place 75 to 80 horizontal wells

on production during 2015 compared to

113 horizontal wells in 2014

– 75% Wolfcamp B wells; remainder split between

Wolfcamp A and Wolfcamp D wells

– Average D&C cost per well: ~$8 MM assuming average

lateral lengths of ~9,000 feet and an average 10% cost

reduction compared to 2014

– Expected to generate EURs averaging ~750 MBOE with

before-tax IRRs up to 55% (excludes carry) at current

strip prices (average oil price of $55 per barrel during

2015)

Pioneer’s Southern Wolfcamp JV Area2015 Drilling Areas

Plan to spud ~45 wells in 2015 utilizing

2-well and 3-well pads

>90% Wolfcamp B

12

918

2237

54

2013 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Continuing to Grow Spraberry/Wolfcamp Production

Spraberry/Wolfcamp Net Production (MBOEPD)1

1) Includes horizontal and vertical production from Pioneer’s northern acreage and the southern Wolfcamp joint venture area (60% Pioneer/40% Sinochem) 2) Q1 production negatively impacted by ~3 MBOEPD due to downtime associated with severe winter weather (~1 MBOEPD FY impact)3) Ethane rejection of ~2 MBOEPD expected throughout 2015 due to low ethane prices

69 horizontal wells placed on production in Q4

− 43 in northern acreage and 26 in southern Wolfcamp

joint venture area

− Also placed 30 vertical wells on production

Q4 production: 115 MBOEPD

− Up 12 MBOEPD compared to Q3 as horizontal

production growth (+17 MBOEPD) more than offset

declines in vertical production (-5 MBOEPD)

− Oil production up 10 MBOPD compared to Q3

2015 production outlook

− Expect production to increase by 20%+

o Growth first-half weighted

o Q4 2015 production expected to be flat vs. Q4 2014

− FY 2015 production reduced by ~3 MBOEPD due to

ethane rejection and Q1 severe winter weather

79

Vertical

Horizontal

2014

99 MBOEPD

86

92

103

115

2015E

119+ MBOEPD2,3


if margins improve

13

Impacted by severe

weather in Q1 and FY

ethane rejection2,3

Field Infrastructure – Tank Batteries & Gas Processing

Tank Batteries / Saltwater Disposal

Slowing pace of construction of new large-scale tank batteries and

saltwater disposal facilities in response to the slowdown in

horizontal drilling

2015 capital program includes ~$215 MM for facilities to support the

high-graded program

Gas Processing

Atlas remains committed to complete a new 200 MMCFPD plant in

Martin County (Buffalo), but has deferred start-up from Q3 2015 to

2016; the additional plant scheduled for 2016 has been deferred

indefinitely

2015 capital program includes ~$70 MM for the Buffalo plant and

gathering system investments for both the Atlas and WTG systems

Brady Sand Mine Expansion

As a result of Pioneer’s reduced proppant requirements due to the

drilling slowdown, expansion of the Brady plant capacity from 750

M tons per year to 2.1 MM tons per year is being deferred until at

least 2016

2015 capital program includes ~$25 MM for maintenance, continued

engineering work and site preparation

DL Hutt Tank Battery

Atlas Edward Gas Processing Plant

Brady Sand Mine

14

Slowing Down Water Project Construction

15

Plans originally called for the initial phase of Pioneer’s

field-wide water transport system to commence in 2015

As a result of the slowdown in Pioneer’s drilling

program, 2015 capital spending is expected to be

$100 MM with activity limited to:

– Construction of feeder line and associated mainline segment

which will move water from an existing third-party Santa

Rosa Aquifer source to Pioneer’s high-graded drilling acreage

in the southern Wolfcamp JV

o Reduces well costs in this area by ~$150 M per well

– Continued engineering and ROW acquisition

Working with the City of Odessa to allow Pioneer to

defer offtake of effluent water

Discussions are continuing with City of Midland to

purchase effluent water when drilling activity increases

Frac Pond

Subsystem

Feeder line

from Midland

Feeder line

from Odessa

Feeder line from 3rd party source (Reagan County)

Main

line

2015

Activity

2015 activity will allow Pioneer to be

prepared for additional construction in

2016 if commodity prices improve

150

127126122

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80 7770 70 68 65 63 62

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17

Eagle Ford Shale WellsAverage 150-Day Cumulative Production (MBOE)

Eagle Ford Shale JV: High-Grading Drilling Activity in 2015

Reducing horizontal rig count to 6 rigs by the

end of February

High-grading drilling activity to areas with the

highest EURs

– Focus will be in Karnes and DeWitt counties where

Pioneer has been drilling the most productive wells

in the Eagle Ford Shale

– Pioneer placed 128 wells on production in 2014

o 78 wells were in Lower targets and 50 wells were in

Upper targets

o Upper targets continue to show similar production to

offset Lower targets

Expect to place 95 to 100 horizontal wells on

production during 2015

– Average D&C cost per well: $7 MM - $8 MM

assuming average lateral lengths of ~5,000 feet and

an average 10% cost reduction compared to 2014

– Expect to generate EURs averaging ~1.3 MMBOE

with before-tax IRRs up to 70% at current strip

prices (average oil price of $55 per barrel during

2015) 16Source: Credit Suisse and HDPI data for wells drilled since July 2013

6 Month Cum Peak BOE> 200,000

150,000 – 200,000

100,000 – 150,000

50,000 – 100,000

< 50,000

JV Acreage

Central Gathering Point

Pipeline Infrastructure

2015 Drilling

Areas

Plan to spud ~85 wells in 2015

utilizing 2-well to 5-well pads

50% Upper / 50% Lower

38

43 47 47 49

2013 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Continuing to Grow Eagle Ford Shale Production

Eagle Ford Shale Net Production (MBOEPD)1

1) Reflects Pioneer’s ~35% share of gross production

2) Commenced ethane rejection in January due to low ethane prices; expected to continue through year-end as a result of weak market conditions; impact on

FY 2015 production forecasted to be ~2 MBOEPD

46 MBOEPD

2014

Eagle Ford Shale net production of 49 MBOEPD

in Q4

− Placed 30 liquids-rich wells on production in Q4

− Production impacted by unplanned CGP downtime,

POP timing and greater-than-anticipated shut-in

production due to offset fracs

2015 production outlook

− Expect production to increase by 9%+

o Production relatively flat throughout the year reflecting

timing of POPs

− FY 2015 production reduced by ~2 MBOEPD compared

to 2014 due to ethane rejection2015E


if margins improve

50+ MBOEPD2

17

Impacted by ethane rejection2

Eagle Ford Shale Condensate Exports

US Department of Commerce confirmed that

condensate processed through a distillation unit

(stabilizer) at PXD’s Eagle Ford Shale central

gathering plants is a petroleum product that may

be exported without a license

Exported ~10 MBOPD gross (~3.5 MBOPD net) of

Eagle Ford Shale condensate during the second

half of 2014 with significantly improved pricing

compared to domestic condensate sales

~20 MBOPD gross (~7 MBOPD net) of condensate

has been committed for export in 2015 under

two contracts with further improved pricing

Processed Eagle Ford Shale condensate has been

sold to Asian and European refining and

petrochemical companies

Distillation Unit

(Stabilizer)

Central Gathering Plant in Karnes County, TX

First Condensate Export Cargo 18

Optimizing Returns in a Lower Oil Price Environment

Cost Reductions Aggressively soliciting cost reductions from suppliers and service companies, including:

– Materials (e.g. casing and tubing, drilling mud, chemicals and guar)

– Freight (e.g. rates and fuel charges)

– Fuel (e.g. rig, fleet and equipment diesel)

– Drilling rig contracts

– Rental equipment (e.g. blowout preventers, coil tubing, etc.)

– Wireline services

Efficiencies Continuing completion optimization testing in the Spraberry/Wolfcamp area for program-wide

implementation

– Increasing clusters per stage

– Optimizing fluid chemistry and proppant concentration

Testing modified 3-string and 2-string casing design in the Upper Wolfcamp B and Wolfcamp A intervals

in southern Wolfcamp joint venture area

– Potential savings of $500 M to $1 MM per well

– Evaluating application on Pioneer’s northern Spraberry/Wolfcamp acreage

Testing dissolvable plug technologies in the Spraberry/Wolfcamp and Eagle Ford Shale areas to reduce

or eliminate coil tubing drill outs after fracture stimulations

– Potential savings of $300 M per well

Already realizing ~10% reduction in drilling costs in 2015 compared to 2014 Expect costs to decline at least 20% by year-end 2015 compared to 2014

19

20

U.S. asset base

High oil exposure from proved reserves + estimated net resource

potential of >11 BBOE

Drilling program focused in core Texas assets

– Spraberry/Wolfcamp Shale

– Eagle Ford Shale

Attractive derivative positions protect cash flow

Strong balance sheet provides financial flexibility to:

– prudently manage through a protracted oil price downturn, or

– quickly ramp up drilling activity if margins improve significantly

PXD Investment Highlights

21

Appendix

Pioneer’s Areas of Operations

22

Eagle Ford Shale

Raton

Northern Spraberry/Wolfcamp

Operating Areas

Southern Wolfcamp JV AreaDallas Headquarters

Current Total Enterprise Value ($B) ~$24

Q4 2014 Production – 50% Oil (MBOEPD) 201

2015E Total Capital Spend, Net ($B) ~$1.85

2015E Cash Flow ($B) ~$1.70

2014 Horizontal Drillbit F&D ($/BOE) $15.51

2014 Reserve Replacement (%) 239%

YE 2014 Proved Reserves (BBOE) 0.8

West Panhandle

Added 177 MMBOE from the drillbit, or 239% of full-

year production, at a drillbit F&D cost of $19.65 per

BOE2

– Reflects significant drilling campaigns in horizontal

Spraberry/Wolfcamp Shale and Eagle Ford Shale

plays

– Drillbit F&D cost for horizontal additions of 157

MMBOE was $15.51 per BOE

Reserve mix

– 100% U.S.

– 44% oil / 21% NGLs / 35% gas

– 81% PD / 19% PUD

Proved Reserves / Production: ~11 years

PD Reserves / Production: ~9 years

23

Pioneer’s Year-End 2014 Proved Reserves1

1) Reflects 2014 SEC pricing (12-month average) of $94.98/BBL for oil and $4.35/MMBTU for gas (NYMEX) as compared to 2013 SEC pricing of $96.82/BBL for oil

and $3.67/MMBTU for gas (NYMEX)2) Excludes PUD reserves removed as a result of vertical Spraberry/Wolfcamp wells no longer expected to be drilled (39 MMBOE), positive price revisions

(12 MMBOE) and reserves added from acquisitions (2 MMBOE)

Year-end 2014 Proved Reserves

(MMBOE)

Spraberry/Wolfcamp 476

Eagle Ford 142

Raton 121

Other 60

Total 799

24

$8.88 $8.45 $8.32 $7.83$8.50

$1.04 $1.68 $1.89$1.66

$1.52

$3.11$3.68 $3.52

$3.35$2.78

$0.55

$0.76 $0.59$0.63 $0.65

Production Costs (per BOE)1

Production & Ad Valorem

Taxes

Workovers

LOE

Third Party Transportation

Natural Gas

Processing

Q3 ’14

$(0.27)

Q4 ’13 Q1 ’14 Q2 ’14

$(0.19)

Q4 2014 production costs

increased slightly compared to

Q3 2014

— LOE increased primarily due to

timing of invoices

— Natural gas processing expense is

primarily related to lower NGL

price realizations on volumes

retained under percentage of

proceeds contracts with third

parties

— Production and ad valorem tax

payments lower due to decline in

commodity prices$(0.42)

$13.39

$14.30

$(0.30)

Q4 ’14

1) All periods presented have been restated to exclude discontinued operations associated with Alaska, Barnett Shale and Hugoton activities

$0.16

$13.90

$13.17 $13.61

25

Pioneer’s Production By Commodity By Area

Q4 '13 Q1 '14 Q2 '14 Q3 '14 Q4 '14Spraberry/Wolfcamp Oil (BOPD) 52,957 58,307 57,893 66,425 76,894

NGL (BOEPD) 16,251 16,693 19,754 21,734 23,956 Gas (MCFD) 65,863 66,770 83,368 86,412 87,630

Total (BOEPD) 80,186 86,128 91,542 102,561 115,455 Eagle Ford Oil (BOPD) 15,922 16,787 17,664 18,038 18,697


Total (BOEPD) 40,248 42,611 46,556 47,253 48,619 Raton Oil (BOPD) - - - - -

NGL (BOEPD) - - - - - Gas (MCFD) 130,077 126,451 125,079 124,451 121,312

Total (BOEPD) 21,679 21,075 20,847 20,742 20,219 West Panhandle Oil (BOPD) 2,896 3,066 2,955 2,481 2,963


Total (BOEPD) 9,154 9,790 9,892 8,161 9,651 South Texas Oil (BOPD) 299 380 1,199 1,970 1,943

NGL (BOEPD) 4 7 11 99 282 Gas (MCFD) 28,438 27,597 28,856 27,024 26,283

Total (BOEPD) 5,043 4,987 6,020 6,573 6,605 Other Oil (BOPD) 55 50 69 60 35

NGL (BOEPD) 335 409 369 322 168 Gas (MCFD) 2,994 3,613 3,231 2,433 1,203

Total (BOEPD) 889 1,062 977 788 404 Total Continuing Ops Oil (BOPD) 72,129 78,589 79,780 88,973 100,532


Total (BOEPD) 157,199 165,653 175,834 186,077 200,953

Continue to use derivatives to mitigate commodity price

exposure in order to ensure funding for development

programs and to maintain strong financial position

– Target >50% on rolling 3 year basis

Continue to use a variety of derivative instruments, but

focus will be on providing floor protection while retaining

upside; primary derivative instruments will be:

– Swaps

– Collars with short puts (three-way collars)

Enter derivative agreements only with counterparties that

are “A” rated or better

Actively monitor credit exposure to each counterparty and

counterparty credit trends

No margin requirements with counterparties

Derivative Philosophy

26

27

Oil Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016

Swaps – WTI (BPD) 82,000 82,000 82,000 82,000 -

NYMEX WTI Price ($/BBL) $71.18 $71.18 $71.18 $71.18 -

Three Way Collars – (BPD)1,2 10,000 15,000 15,000 15,000 73,000

NYMEX Call Price ($/BBL) $94.54 $97.69 $97.69 $97.69 $80.67

NYMEX Put Price ($/BBL) $81.95 $82.97 $82.97 $82.97 $70.70

NYMEX Short Put Price ($/BBL) $67.00 $69.67 $69.67 $69.67 $49.41

% Total Oil Production ~90% ~90% ~90% ~90% N/A3

Open Commodity Derivative Positions as of 2/6/2015

1) When NYMEX price is above call price, Pioneer receives call price. When NYMEX price is between put price and call price, Pioneer receives NYMEX price. When NYMEX price is between the put price and the short put price, Pioneer receives put price. When NYMEX price is below the short put price, Pioneer receives NYMEX price plus the difference between the put price and short put price

2) Counterparties have the option to extend 5,000 BPD of 2015 collar contracts with short puts for an additional year with a call price of $100.08/BBL, a put price of $90.00/BBL and a short put price of $80.00/BBL. The option to extend is exercisable by the counterparties on December 31, 2015

3) Forecasted oil production for 2016 and related coverage level dependent on future market conditions4) Not a derivative5) Transaction volumes tied to production from specific leases; current oil production (net to Pioneer) associated with these leases is >20 MBOPD

Midland-Cushing Fixed Oil Differential Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016

#1 Market Transaction4 35,000 35,000 35,000 35,000 35,000

Price Differential ($/BBL) $(1.75) $(1.75) $(1.75) $(1.75) $(1.75)

#2 Market Transaction4 Based on specific lease production volumes5

Price Differential ($/BBL) $(1.04) $(1.04) $(1.04) $(1.04) $(1.04)

Oil coverage: ~90% in 2015

28


1) Represent swap contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices2) Represent swap contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices3) Forecasted NGL and liquid production for 2016 and related coverage level dependent on future market conditions

Ethane Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016

Swaps – (BPD)1 3,278 5,000 5,000 5,000 4,000

Mont Belvieu Swap Price ($/BBL) $7.83 $7.83 $7.83 $7.83 $12.29

Propane Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016

Swaps – (BPD)2 5,572 8,500 8,500 8,500 2,000

Mont Belvieu Swap Price ($/BBL) $21.48 $21.48 $21.48 $21.48 $21.63

% Total NGL Production ~25% ~35% ~35% ~35% N/A3

% Total Liquids ~75% ~75% ~75% ~75% N/A3

29

Gas Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016

Swaps - (MMBTUPD) 20,000 20,000 20,000 20,000 70,000

NYMEX Price ($/MMBTU)1 $4.31 $4.31 $4.31 $4.31 $4.06

Three Way Collars – (MMBTUPD)1,2 285,000 285,000 285,000 285,000 20,000

NYMEX Call Price ($/MMBTU) $5.07 $5.07 $5.07 $5.07 $5.36

NYMEX Put Price ($/MMBTU) $4.00 $4.00 $4.00 $4.00 $4.00

NYMEX Short Put Price ($/MMBTU) $3.00 $3.00 $3.00 $3.00 $3.00

% Total Gas Production ~90% ~90% ~90% ~90% N/A3


1) Represents the NYMEX Henry Hub index price or approximate NYMEX price based on historical differentials to the index price at the time the derivative was entered into

2) When NYMEX price is above call price, Pioneer receives call price. When NYMEX price is between put price and call price, Pioneer receives NYMEX price. When NYMEX price is

between the put price and the short put price, Pioneer receives put price. When NYMEX price is below the short put price, Pioneer receives NYMEX price plus the difference

between put price and short put price

3) Forecasted gas production for 2016 and related coverage level dependent on future market conditions

Gas Basis Swaps Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016

Spraberry (MMBTUPD) 10,000 10,000 10,000 10,000 -

Price Differential to NYMEX ($/MMBTU) $(0.13) $(0.13) $(0.13) $(0.13) -

Eagle Ford (MMBTUPD) 20,000 20,000 20,000 20,000 -

Price Differential to NYMEX ($/MMBTU) $(0.00) $(0.00) $(0.00) $(0.00) -

Mid-Continent/Rocky Mountain (MMBTUPD) 95,000 95,000 95,000 95,000 15,000

Price Differential to NYMEX ($/MMBTU) $(0.24) $(0.24) $(0.24) $(0.24) $(0.32)

Gas coverage: ~90% for 2015

$30

$40

$50

$60

$70

$80

$90

$100

$30 $40 $50 $60 $70 $80 $90 $100

Realized P

rice (

$/B

BL)

NYMEX Oil Price ($/BBL)

NYMEX Oil Three-Way Collar Realization

Three-Way Collars ($50 by $70 by $80 Example)

Three way collars protect downside while providing upside exposure30

Short-Put at

$50/BBL

Long-Put at

$70/BBLShort-Call at

$80/BBL

Potential

Gain

Realize NYMEX plus $20/BBL

(difference between long-put

and short-put) Realize $70/BBL

Realize

NYMEX Price

Realize $80/BBL

Potential

Opportunity

Loss

OZONA

PLATFORM

31

Geologic Provinces of the Permian Basin

PEDERNAL UPLIFT &

ROOSEVELT POSITIVE

DEVIL’S

RIVER

UPLIFT

Permian Basin is composed of multiple uplifts and basins that formed during the Pennsylvanian and early Permian ages

Spraberry/Wolfcamp Shale and deeper intervals are located in the Midland Basin of the Permian Basin

Spraberry/Wolfcamp field was discovered in 1943 with production commencing in 1949

Basin

Basement

Uplift

Shelf

Thrust Belt

Platform Carbonate

Shelf Edge Carbonate

Slope Sediments & Reef Talus

Carbonate Debris Flows

Carbonate Gravity Flows

Land

Clastic Detrital

Clastic Slope Sediments

Clastic Gravity Flows

Delta

Pelagic Sediments

Silt Cloud in Suspension

Anaerobic Zone

(Organic-rich Sediments)

Basinal Sediments

Wolfcamp Map

San Simon

Channel

North Basin

Platform

Glasscock

Nose

Marathon

Thrust Belt

Fluvial - Deltaic

Platform

Carbonate

Clastic

Slope

Land

Carbonate Slope

Debris

Flow

Carb

Gravity Flow

Clastic

Gravity Flow

Pelagic Sed.

Platform

Carbonate

Land

Land

CBP

Midland

Basin

Marathon

Thrust Belt

North

Older

Wolfcamp

Clastics

Wolfcamp Depositional Model – Midland Basin

Midland

Source: Adapted from Handford, 1981 32

Regional Cross Section D-D’

Spraberry

Spraberry

WC B,C1

WC-D

LSSLSS

Strawn

Miss

Woodford

Woodford

WC-D

Horseshoe

Atoll

SouthNorth

WC-AWC-A

WC-Upper B

WC-C

Ozona Platform

Atoka

Jo Mill Shale Jo Mill Shale

Successful Horizontal Wells in the Play

Future Horizontal Play

13 horizontal play intervals identified (so far)

10 intervals have been tested successfully

3 additional intervals remain to be tested

D D’

Big Lake Fault

Calvin Fault

Barnettford

WC-Lower B

Miss

Woodford

Clear Fork

MSSMSS

33

Midland Basin: Stacked Play Potential

“Delta log R” (excess electrical resistance)

Red intervals indicate hydrocarbons

Petrophysical analysis indicates significantly more oil in place

in the Wolfcamp and Spraberry Shale intervals in the Midland

Basin compared to other major U.S. shale oil plays

200 f

tEagle Ford

Condensate

Barnett

ComboMarcellus

Barnett

Miss Lime

Woodford

Wolfcamp D

“Cline”

Wolfcamp A

Wolfcamp B

L. Spraberry

Shale

M. Spraberry

Shale

Clear Fork

Bakken

Jo Mill Shale

Midland Basin

Source: PXD

Dean

Wolfcamp C

U. Spraberry

Atoka

Strawn

Niobrara

34

Spraberry/Wolfcamp Rig Count

Source: Rig count data provided by Baker Hughes, 02/13/15

Vertical Rigs

Horizontal Rigs

Counties: Andrews, Borden, Crockett, Dawson, Ector, Gaines, Glasscock, Howard, Irion, Martin,

Midland, Mitchell, Reagan, Schleicher, Scurry, Sterling, Tom Green and Upton

96% Vertical Rigs

41% Vertical Rigs

(dropped over 100 vertical

rigs since mid-2014)

4% Horizontal Rigs 59% Horizontal Rigs

(peaked at 162 rigs in

late-2014)

35

Production Growth Profiles For 3 Largest U.S. Oil Shale Plays

Eagle Ford

161 Horizontal Rigs

(down from max of 203 rigs in 2014)

Bakken

127 Horizontal Rigs


Spraberry/Wolfcamp

115 Horizontal Rigs


Spraberry/Wolfcamp initial horizontal growth trajectory similar to Bakken and Eagle Ford

Note: Production data is from IHS and represents incremental production for the play beginning when horizontal drilling activity began in earnest; Rig count data

from Baker Hughes as of 02/13/15; Spraberry/Wolfcamp includes selected counties identified on slide titled “Spraberry/Wolfcamp Rig Count”; Initial month is

November 2010 for Spraberry/Wolfcamp, April 2008 for Eagle Ford and January 2003 for Bakken

Includes Horizontal Wells Only

36

Spraberry/Wolfcamp Production History

From 2009 to 2012, production growth primarily attributable to increased vertical activity

Post 2012, production growth expected to be driven by horizontal activity

Source: IHS Energy monthly data through October 2014 for the Spraberry, Credo East, Garden City South and Lin Fields; 2-stream production data

Includes Vertical and Horizontal Wells

37

Spraberry/Wolfcamp production has

increased ~630,000 BOEPD since 2009

Drilling Results Confirming Pioneer’s Midland Basin Sweet Spot

38

PXD Wolfcamp B Prospectivity Map (Early 2013)

Source: ITG Investment Research

2014 ITG Research Report

Wolfcamp (All Zones) Test Rates

Test R

ate

(BO

EPD

/1000’ la

tera

l)

Tier 1 Tier 2 Pioneer Land

Pioneer Wolfcamp B wells

Wolfcamp B depth contour

Lower

Higher

Source: Internal Pioneer developed in early 2013

GC

Market

Wink

Seaw

ay

Keysto

ne S

outh

Permian

Basin

Cushing

Crude Pipeline Capacity to Gulf Coast

39

Operator Origin Destination Name Capacity Time Frame

Plains Permian Cushing Basin 450,000

Oxy Permian Cushing Centurion 75,000

Sunoco Permian GC West Texas Gulf 400,000

Kinder Morgan Permian El Paso Wink 120,000

Magellan Permian GC Longhorn 250,000

Magellan Permian GC BridgeTex 300,000

Total 1,595,000

Magellan Permian GC Longhorn-add 25,000 2Q 2015

Plains Permian Corpus Cactus 200,000 2Q 2015

Sunoco Permian GC Permian Express II 200,000 3Q 2015

Total 425,000

Operator Origin Destination Name Capacity Time Frame

ENB/Enterprise Cushing GC Seaway 850,000

Transcanada Cushing GC Gulf Coast 830,000

Total 1,680,000

Permian Basin Crude Takeaway Capacity

Cushing to Gulf Coast Pipeline Takeaway

Current

Current

Planned

Spraberry/Wolfcamp Midstream Infrastructure

40

Gas Processing

Atlas System

− PXD has ~27% interest

− Current capacity: 655 MMCFD1

o Includes new Edward plant

online Q3 2014 (+200

MMCFD)

− PXD production makes up ~37%

of throughput

− Buffalo Plant in Martin County

deferred to 2016 (+200 MMCFD)

Sale Ranch (WTG)

− PXD has ~30% interest

− Current capacity: 320 MMCFD2

o Includes new Martin County

Plant online Q1 2015

(+200 MMCFD)

− PXD production makes up ~13%

of Sale Ranch throughput

Pipeline NGL Takeaway

to Mont Belvieu

Chaparral & West Texas

Pipelines

− PXD production throughput of

~13 MBPD

Lone Star Pipeline

− PXD production throughput of

~14 MBPD

− Connect to all PXD gas

processing plants

Mont Belvieu fractionation

capacity at ~1.7 MMBPD

− Capacity additions of

~0.5 - 1.0 MMBPD planned

during 2015 – 2018

Processing and takeaway capacity sufficient to

support Pioneer’s production in the Midland Basin

1) Wet gas stream with ~160 BBL/MMSCF NGL yield

2) Wet gas stream with ~135 BBL/MMSCF NGL yield

Existing NGL Pipeline

Benedum/Edward

Sale Ranch

PXD Acreage

Spraberry Field

Midkiff

Driver

Buffalo

Existing NGL Pipeline

41

Reserves Audit, F&D Costs and Reserve Replacement

An audit of proved reserves follows the general principles set forth in the standards pertaining to the estimating and

auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers ("SPE"). A reserve

audit as defined by the SPE is not the same as a financial audit. Please see the Company's Annual Report on Form 10-

K for a general description of the concepts included in the SPE's definition of a reserve audit.

"Drillbit finding and development cost per BOE," or “drillbit F&D cost per BOE,” means the summation of exploration

and development costs incurred divided by the summation of annual proved reserves, on a BOE basis, attributable to

discoveries and extensions (excludes purchases of minerals-in-place) and revisions of previous estimates. Revisions

of previous estimates excludes vertical Spraberry/Wolfcamp PUDs removed and price revisions. Consistent with

industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.

“Drillbit reserve replacement” is the summation of annual proved reserves, on a BOE basis, attributable to

discoveries and extensions (excludes purchases of minerals-in-place) and revisions of previous estimates divided by

annual production of oil, NGLs and gas, on a BOE basis. Revisions of previous estimates excludes vertical

Spraberry/Wolfcamp PUDs removed and price revisions.

42

Certain Reserve Information

Cautionary Note to U.S. Investors --The SEC prohibits oil and gas companies, in their

filings with the SEC, from disclosing estimates of oil or gas resources other than

“reserves,” as that term is defined by the SEC. In this news release, Pioneer includes

estimates of quantities of oil and gas using certain terms, such as “resource potential,”

“net recoverable resource potential,” “estimated ultimate recovery,” “EUR,” “oil-in-

place” or other descriptions of volumes of reserves, which terms include quantities of

oil and gas that may not meet the SEC’s definitions of proved, probable and possible

reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in

filings with the SEC. These estimates are by their nature more speculative than

estimates of proved reserves and accordingly are subject to substantially greater risk

of being recovered by Pioneer. In addition, the SEC permits U.S. companies with mining

operations, in their filings with the SEC, to disclose only “reserves,” which are mineral

deposits that a company can economically and legally extract or produce. The SEC

normally only permits users to report mineralization that does not constitute reserves

as in-place tonnage and grade without reference to unit measures. U.S. investors are

cautioned not to assume that Pioneer’s estimates of resource potential of mineral

deposits reflect economically recoverable quantities. Any inaccuracy in our estimates

related to our mineral reserves and non-reserve mineral deposits could result in lower

than expected sales and higher than expected costs. U.S. investors are urged to

consider closely the disclosures in the Company’s periodic filings with the SEC. Such

filings are available from the Company at 5205 N. O'Connor Blvd., Suite 200, Irving,

Texas 75039, Attention: Investor Relations, and the Company’s website at

www.pxd.com. These filings also can be obtained from the SEC by calling 1-800-SEC-

0330.

2015-02-17 february investor presentation

Documents

pioneers ability

weather risks

number of risks

unforeseen risks

purchasers of pioneers

pioneers actual results

hugoton production

production forecasts